High Annular Area Low Friction Stabilizer Design

ABSTRACT

A low friction stabilizer having a body and a plurality of small contact pads configured to function with the effectiveness of a single, larger contact pad is described. The assemblage and configuration of the small contact pads enable the performance of stabilization while reducing rotational drag and while allowing high annular flow around the stabilizer.

FIELD

Embodiments usable within the scope of the present disclosure relate, generally, to drill string stabilizers configured within drill strings and used in earth boring operations, and in particular designs of stabilizers which reduce rotational drag and improve drilling fluid flow during operation.

BACKGROUND OF THE INVENTION

Drill string stabilizers are well-known in the field of oil and gas well drilling as a means to avoid unintentional destabilizing forces known to occur in drilling operations. Stabilizers are commonly used to reduce vibrations, sidetracking and other unwanted effects of drilling through geologic formations. The use of stabilizers, in addition, can aid in maintaining the orientation of the drill bit as well as the drill string during operation, reducing the possibility of drift.

Stabilizers operate by making physical contact with the interior wall of the borehole. Typically, stabilizers are constructed with one or more ribs, ridges, blades, or gage pads which protrude from the main body of the tool. These protuberances are placed in physical contact with the borehole wall, thereby providing stability. Contact, however, is made at the cost of rotational drag forces created between the protuberances and the borehole wall. Being placed in direct contact with the walls of the borehole, stabilizer protuberances must be constructed of durable materials. When used to stabilize the drill string within the borehole, protuberances are typically constructed from or with wear resistant materials. Rotational drag forces created by the contact of the protuberances with the borehole wall can lead to damage or fouling of the stabilizer. Further, vibration caused by these rotational drag forces can lead to breakage of some other parts of the drill string.

Stabilizers can be designed to hold the drill string in a fixed orientation or can be designed to allow orientational changes, such as are necessary in directional drilling. Variation of the length of the protuberances along the main body of the tool allows the drill string either to be held in a fixed position relative to direction, such as when longer protuberances are used, or to allow flexing of the drill string to allow orientation or reorientation of the drill string during directional drilling, such as when shorter protuberances are used.

Moreover, stabilizers must be constructed so as not to obstruct the flow of drilling fluid, which is pumped into the borehole in part to cause the removal of pieces of rock cut away from the geologic formation by the drill bit, thereby cleaning the borehole. An interstitial area is commonly placed between the protuberances, through which the drilling fluid is circulated, carrying rock cuttings and other debris with the drilling fluid. Such an interstitial area between two protuberances known in the art would be generally of the same shape as the protuberances. That is, if the protuberances are straight, the interstitial area will be straight lithe protuberances are curviform, the interstitial area between them will be curviform.

While stabilizers must, therefore, be designed to withstand the harsh conditions of the borehole during drilling operations, they must also be designed not to impede the flow of drilling fluid, which is equally necessary for effective drilling operations. Current stabilizer designs are typically seen either to contain large, straight protuberances, which allow the stabilizer to stand up against frictional forces, or stylized or curviform designs which reduce frictional forces but impede the flow of drilling fluid.

Specifically, current stabilizer designs are generally seen to contain large, straight protuberances designed for soft formations and maximum fluid flow or bypass area or they contain spiral-shaped or helical protuberances with larger contact surfaces to retain outer diameter and maximize centralization.

In typical stabilizer design, longer and wider protuberances, whether straight or curviform, improve stability but impede the passage of drilling fluid. Longer protuberances likewise typically reduce flexing of the drill string, while shorter protuberances allow more flexing. Protuberance length is determined by the need for directional drilling capabilities of the drill string. Longer and/or wider protuberances also increase rotational drag forces. Longer and wider protuberances, in reducing or impeding drilling fluid flow, can lead to cleaning issues or cause cuttings to foul or aggregate and pack off the fluid passage below the projections. At the same time, the constricted space between protuberances causes increased fluid speed between the protuberances, which may fluffier lead to erosion or abrasion of the protuberances caused by the impact of rock cuttings or other debris against the sides of the protuberances. Exemplary designs of stabilizers are found in U.S. Pat. No. 3,642,079, U.S. Pat. No. 5,330,016, and Chinese patent publication 201,635,674. These examples reflects designs in which stabilizer protuberances are curviform (the '079 patent), straight ('016) or a combination of straight and curviform design elements (the '674 patent).

There is a need for a stabilizer design which effectively moderates these requirements of sturdy design for longevity, a reduced frictional contact surface between the projections and the wall of the borehole, flexibility as to directional containment or directional reorientation, and protuberance design which does not impede or reduce the flow of drilling fluid circulating in the borehole.

The present invention incorporates design elements improving the performance characteristics of the stabilizer as to each of the above needs.

SUMMARY OF THE INVENTION

The present invention optimizes stabilizer protuberances in the form of contact pad design to reduce friction, increase fluid flow between such stabilizer contact pads and allow variable flexure without compromising stabilizer strength. The stabilizer contact pads of this invention are based in part on curviform stabilizer pad design while allowing linear flow for drilling fluid axially along the body of the stabilizer. Instead of a single, elongate and curved stabilizer pad, the present invention uses a plurality of smaller contact pads assembled in the approximate shape of a single, curviform stabilizer pads but in which the assemblage of a plurality of contact pads results in a stabilizer pad with reduced surface area and improved flow characteristics.

BRIEF DESCRIPTION OF THE DRAWINGS

In the detailed description of various embodiments of the present invention presented below, reference is made to the accompanying drawings, in which:

FIG. 1 depicts a perspective view of an exemplary stabilizer known in the art.

FIG. 2A depicts a cross-sectional view of the exemplary stabilizer known in the art.

FIG. 2B depicts a side view of the exemplary stabilizer known in the art.

FIG. 3 depicts a perspective view of an embodiment of the high annular area, low friction stabilizer design usable within the scope of the present disclosure.

FIG. 4 depicts a perspective view of an alternative embodiment of a high annular area, low friction stabilizer design usable within the scope of the present disclosure.

FIG. 5 depicts a perspective view of an additional alternative embodiment of a high annular area, low friction stabilizer design usable within the scope of the present disclosure.

FIGS. 6A and 6B depict a cross-sectional view and a side view of the embodiment of the high annular area, low friction stabilizer as shown on FIG. 4.

FIGS. 7A and 7B depict a cross-sectional view and a side view of the embodiment of the high annular area, low friction stabilizer as shown on in FIG. 3.

FIG. 8A depicts a flow pattern of the known stabilizer depicted in FIG. 1.

FIG. 8B depicts a flow pattern of the alternative embodiment of the high annular area, low friction stabilizer design depicted in FIG. 4.

FIG. 8C depicts a flow pattern of the preferred embodiment of the high annular area, low friction stabilizer design depicted in FIG. 3.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Before explaining selected embodiments of the present inventions in detail, it is to be understood that the present invention is not limited to the particular embodiments described herein and that the present invention can be practiced or carried out in various ways.

FIG. 1 depicts a perspective view of a stabilizer known in the art. A hollow or semi-hollow body 14 contains a proximal end 12 a and a distal end 12 b. Each of these ends 12 a and 12 b provide means for connecting the body 14 to another drill string element, not depicted. Connection means are not substantive to the present invention and are not described in detail here. The majority of the body 14 comprises an elongate tubular structure 13, the diameter of which is fixed, in general, except where protuberances in the form of stabilizer contact pads are placed. The body 14 comprises three substantially identical contact pads 10, each of which contact pads are curviform in shape and are positioned substantially axially between the proximal end 12 b and the distal end 12 a. The length of each contact pad 10 is less than the length of the body 14, with the length of a particular contact pad 10 depending upon the specific application of the stabilizer. Longer contact pads 10 are used in drilling operations in which less flexure is required. Shorter contact pad 10 length is used in drilling operations in which more flexure is required, such as in directional drilling operations. Between each contact pad 10 is a junk slot 11 through which drilling fluid containing rock cuttings and other materials flow during drilling operations.

FIGS. 2A and 2B depict cross-sections of the contact pads 10 and junk slots 11 as shown in FIG. 1. Of significance in these figures is the curviform nature of each of the contact pads 10 as well as junk slots 11. The curviform nature of each of these results in there being no straight path in any junk slot 11 from the proximal end to the distal end of body 14.

FIG. 3 depicts a perspective view of a preferred embodiment of the present invention. This preferred embodiment comprises a body 34, containing a proximal end 32 a and a distal end 32 b, each of which having connecting means to other or additional drill string components not described here. A plurality of interrupted contact pads 30 are placed on the body 34. Junk slots 31 are co-located with the contact pads 30, being formed naturally by the placement of any contact pad 30 in close proximity of any other contact pad 30. In this preferred embodiment, one contact pad 30 may be paired with a closely positioned second contact pad 30, although this is not necessarily so in other embodiments of the invention. The placement of the contact pads 30 is such that a series of the contact pads 30 are laid out so as to approximate the curviform contact pad of FIG. 1. To each of the contact pads 30 have been affixed one or more diamond wear elements 33.

FIG. 4 depicts a perspective view of an alternative embodiment of the present invention. Body 43 provides proximal end 42 a and distal end 42 b thereof in FIG. 4, a plurality of contact pads 40 and junk slots 41 are laid out in a curviform pattern similar to that as shown in FIG. 3. In FIG. 4, however, each contact pad 40 is larger than each contact pad 30 on FIG. 3, resulting in fewer contact pads on the body 43. To each of the contact pad 40 have been affixed one or more diamond wear elements 44. In this embodiment, the contact pads 40 are not associated pairwise as in FIG. 3.

FIG. 5 depicts a perspective view of an additional alternative embodiment of the present invention. Body 54 provides proximal end 52 a and distal end 52 b. In FIG. 5, the size, shape and orientation of the contact pads 50 and junk slots 51 are identical to the corresponding features shown on FIG. 4. FIG. 5 reflects the construction of the invention per FIG. 4 without diamond wear elements 44. Similarly, the preferred embodiment of FIG. 3 may be constructed without diamond wear elements 33.

FIG. 6A depicts a cross-section of the embodiment as shown on FIG. 4. Contact pads 40 and junk slots 41 are shown. FIG. 7A depicts a cross-section of the preferred embodiment as shown on FIG. 3, similarly depicting contact pads 30 and junk slots 31.

FIG. 6B depicts a side-view of the embodiment as shown on FIG. 4 showing the layout of the contact pads 40 and junk slots 41. The substantially curviform layout of the plurality of the contact pads 40 is shown. FIG. 7B depicts a similar side-view of the preferred embodiment as shown on FIG. 3.

FIG. 8A depicts a side-view as shown on FIG. 21B highlighting the flow path F1 of drilling fluid through a junk slot 11 FIG. 8B depicts a side-view as shown on FIG. 6B highlighting the flow path F2 of the drilling fluid through the junk slots 41. A similar depiction of the flow path F3 of drilling fluid through the junk slots 31 on FIG. 7B is depicted in FIG. 8C.

The shortcomings of the exemplary stabilizer design depicted in FIG. 1 are evident in that figure. In order to provide stability and/or reduce flexibility, the contact pads 10 must be of a certain length. The curviform shape of the contact pads 10 aid in reducing rotational drag when the upper surfaces of the contact pads are placed against the wall of the borehole during drilling operations. The contact site 15 of the contact pad which is in contact with the wall of the borehole is shown in FIG. 2A. Rotational drag relates directly to the total surface combined surface area of the three contact pads 10. In the known stabilizer, the total area of the three contact pads in contact with the wall of the borehole is approximately 77 square inches. The total volume of the junk slots 11 in the known stabilizer is approximately 53 cubic inches.

As shown on FIGS. 3, 7A, 7B and 8C, the design of the preferred embodiment significantly changes that. The present invention uses a plurality of small contact pads 30 manufactured or affixed on the body 34 and set, thereon in approximately curviform form using a series of substantially pair-wise contact pads 30 such that stability or flexure can be achieved depending on the overall length and number of the contact pads. However, the plurality of contact pads 30 allows a, total area in contact with the wall of the borehole to be substantially less than required in the exemplary embodiment of FIGS. 1, 2A, 2B and 8A. In the preferred embodiment of FIG. 3, for example, the total area of the contact pads 30 in contact with the wall of the borehole is approximately 46 square inches, while maintaining the same contact length. Similarly, the volume of the junk slots 31 is increased proportionally to the decreased surface area of the contact pads 30. In the preferred embodiment shown on FIG. 3, the volume of the junk slots 31 is approximately 77 cubic inches. Specific sizes, shapes, and configurations of assembled features may be modified so as to increase or decrease the total area of the contact pads 30 or the volume of the junk slots 31 as indicated by a particular drilling operation. Likewise, the shape or flow pattern through the junk slots 31 may be modified by the specific placement of the assembled features.

Robustness of the stabilizer depicted in FIG. 3 is maintained by the use of superhard materials for the stabilizer in general and the contact pads 30 in particular.

The layout of the plurality of contact pads 30 on FIG. 3 is approximately uniform and substantially similar to the curviform design of the known stabilizer shown on FIG. 1. A critical advantage of the present invention is the ability to create and maintain substantially straight flow patterns of drilling fluid between and around the contact pads 30 during drilling operations. As depicted in FIG. 8B and FIG. 8C, embodiments of the invention include contact pads design such that junk slots 41 and 31, respectively, and flow paths F3 and F2, respectively, run unimpeded from end to end of the body 44 and 34 of each embodiment. Unimpeded flow substantially improves operation in multiple ways. First, unimpeded flow improves the ability of the drilling, fluid to remove rock cuttings by avoiding contact between rock cutting and the sides of contact pads. In curviform contact pads, such as depicted in FIG. 8A, rock cuttings must change direction as the flow path F1 changes direction, increasing the chance for contact with the side of a contact pad.

Further, in each of the embodiments illustrated on FIGS. 3, 4 and 5, increased junk slot volume over the prior art stabilizer of FIG. 1 allows an increase of overall flow of drilling fluid In the known stabilizer of FIG. 1, the small volume of junk slots 11 reduces flow overall, which may result in rock cuttings and other debris falling out of suspension and not being removed from the borehole. By contrast, the increased volume of junk slots 31, 41 and 51 in the present invention depicted in FIGS. 3, 4 and 5 reduces the chance that rock cuttings or other debris may foul or obstruct the fluid passages in the respective junk slot areas. These larger junk slots likewise reduce the tendency of the drilling fluid flow to create areas of turbulent flow, which can increase energy consumption needed to cause the drilling fluid to flow.

The configuration of contact pads and junk slots illustrated on FIGS. 3, 4 and 5 reflect similar improvements in operation during tripping. It is well known in the field that known stabilizer contact pads drag against the low side of the wall of the borehole when the drill string is removed from the borehole. This drag may result in fouling of the stabilizers caused by balling or packing off the contact pads by the accumulation of particles on such contact pads when pulled through the borehole. In the present invention, as illustrated on FIGS. 3, 4 and 5, when the stabilizer is tripped out of the well, the drill string is not in rotation. As such, the contact pads 30, 40 and 50, respectively, are aligned vertically, with corresponding channels free of protuberances similarly aligned. This allows cuttings to move unobstructed past the protuberances without any change in trajectory required for spiral pads of traditional configuration. In the event debris starts to accumulate against the side of any of the contact pads 30, 40 and 50, respectively, such debris is removed by the drilling fluid as the stabilizer is pulled through the drilling fluid, thereby reducing the chance for balling or packing off.

The configuration as to contact pads 30, 40 and 50, and junk slots 31, 41, and 51 on FIGS. 3, 4 and 5 is also advantageous in horizontal and extended reach wells where beds of cuttings exist in the annulus during drilling. The positioning of the contact pads 30, 40 or 50 is such that they form an interrupted screw shape. Thus when the stabilizer is lying on the low side of a wellbore and rotated, the contact pads effectively push the cuttings towards surface and above each stabilizer. The straight flow channels existing between the contact pads (see FIGS. 8B and 8C) contribute a hydraulic force that is longitudinally oriented, which assists the screw-type arrangement of the contact pads in forcing bedded cuttings upwards. This helps to reduce or spread out the beds of cuttings in these wells, where rotating torque is a large limitation to drilling depth, by pushing them towards the surface as each stabilizer is rotated.

While various embodiments of the present inventions have been described with emphasis, it should be understood that within the scope of the appended claims, the present invention might be practiced other than as specifically described herein. 

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 5. A rotary drill string stabilizer for use in drilling a bore hole comprising: a tubular structure having means adapted to secure the structure in a bottom hole apparatus, an axial flow passageway formed through said stabilizer through which drilling fluid can flow toward the drill bit of the bottom hole apparatus; the tubular structure being smaller in diameter than the bore hole being drilled and on which are disposed a plurality of positioned contact pads, said plurality of positioned contact pads being in frictional contact with the inner diameter of the bore hole being drilled the plurality of said contact pads being positioned in a lesser plurality of intersticed circumferential helical blades along the tubular structure and further the placement of contact pads on the tubular structure resulting in linear junk slots through the intersticed circumferential helical blades.
 6. The rotary drill string stabilizer of claim 5 in which the contact pads are disposed on the tubular structure pair-wise.
 7. The rotary drill string stabilizer of claim 5 in which a smaller number of larger contact pads are disposed in a plurality of circumferential helical blades.
 8. The rotary drill string stabilizer of claim 6 in which a larger number of smaller contact are disposed in a plurality of generally helical blades.
 9. The rotary drill string stabilizer of claim 5 in which the intersticed contact pads create reduced frictional loss during operation.
 10. The rotary drill string stabilizer of claim 6 in which the intersticed contact pads create reduced frictional loss during operation.
 11. The rotary drill string stabilizer of claim 5 in which intersticed contact pads create a large annular junk slot volume.
 12. The rotary drill string stabilizer of claim 6 in which the intersticed contact pads create a large annular junk slot volume.
 13. The rotary drill string stabilizer of claim 5 in which a shorter length of the intersticed circumferential helical blades along the longitudinal axis of the tubular structure allows increased drill string flexibility.
 14. The rotary drill string stabilizer of claim 5 in which a longer length of the intersticed circumferential helical blades along the longitudinal axis of the tubular structure allows decreased drill string flexibility.
 15. The rotary drill string stabilizer of claim 6 in which a shorter length of the intersticed circumferential helical blades along the longitudinal axis of the tubular structure allows increased drill string flexibility.
 16. The rotary drill string stabilizer of claim 6 in which a longer length of the intersticed circumferential blades along the longitudinal axis of the tubular structure allows decreased drill string flexibility.
 17. A rotary drill string stabilizer comprising a tubular structure on which are disposed contact pads in a plurality of helical blades approximating the size and shape of a solid helical blades and in which junk slots are formed between the contact pads parallel to the longitudinal axis of the tubular structure, which junk slots are approximately linear along the longitudinal axis of the tubular structure.
 18. The rotary drill string stabilizer of claim 17 in which a smaller number of larger contact pads are disposed in a plurality of circumferential helical blades.
 19. The rotary drill string stabilizer of claim 17 in which a larger number of smaller contact pads are disposed in a plurality of circumferential helical blades.
 20. The rotary drill string stabilizer of claim 17 in which the use of intersticed contact pads result in reduced frictional loss with no loss of drill string stability.
 21. The rotary drill string stabilizer of claim 17 in which the intersticed contact pads create a large annular junk slot volume.
 22. The rotary drill string stabilizer of claim 17 in which the contact pads are disposed on the tubular structure pair-wise.
 23. A rotary drill string stabilizer for use in drilling a bore hole comprising: a tubular structure having means adapted to secure the structure in a bottom hole apparatus, the generally tubular structure being smaller in diameter than the bore hole being drilled and on which are disposed a plurality of positioned contact pads, said plurality of positioned contact pads being sufficiently radially sized to be in frictional contact with the inner diameter of the bore hole being drilled a sufficient number of said contact pads being positioned in a lesser plurality of intersticed circumferential helical blades along the tubular structure and further linear junk slots between contact pads which allow tripping of the drill string with reduced fouling, balling or packing off. 